Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in Canada and Venezuela. Oil sands are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as “bitumen,” but which may also be called heavy oil or tar.
The crude bitumen contained in the Canadian oil sands is described as existing in the semi-solid or solid phase in natural deposits. The viscosity of bitumen in a native reservoir can be in excess of 1,000,000 cP. Regardless of the actual viscosity, bitumen in a reservoir does not flow without being stimulated by methods such as the addition of solvent and/or heat. At room temperature, it is much like cold molasses.
Due to their high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow in order to produce and transport them. Heat is commonly used to lower viscosity and induce flow. One common way to heat bitumen is by injecting steam into the reservoir. Steam Assisted Gravity Drainage (SAGD) is the most extensively used technique for in situ recovery of bitumen resources in the McMurray Formation in the Alberta Oil Sands and other reservoirs containing viscous hydrocarbons. In a typical SAGD process, shown in FIG. 1, two horizontal wells are vertically spaced by 4 to less than 10 meters (m). The production well is located near the bottom of the pay and the steam injection well is located directly above and parallel to the production well. In SAGD, steam is injected continuously into the injection well, where it rises in the reservoir and forms a steam chamber.
With continuous steam injection, the steam chamber will continue to grow upward and laterally into the surrounding formation. At the interface between the steam chamber and cold oil, steam condenses and heat is transferred to the surrounding oil. This heated oil becomes mobile and drains, together with the condensed water from the steam, into the production well due to gravity segregation within the steam vapor and heated bitumen and steam condensate chamber.
Another option to lower oil viscosity is to dilute the viscous oil by injecting a solvent, preferably an organic solvent. As the solvent is dissolved and mixed with the oil, the low viscosity diluted oil can be recovered.
Vapor Extraction (VAPEX) can also be used to extract heavy oil. It is similar to the process of SAGD, but instead of injecting hot steam into the oil reservoir, hydrocarbon solvents are used, and the hydrocarbon solvent is typically captured and recycled. A typical VAPEX process is shown in FIG. 2. Because neither heat, nor water are used in VAPEX, it conserves on energy and water usage, although solvent contributes significantly to cost.
Another development combines aspects of SAGD and VAPEX. In Expanding Solvent-SAGD (ES-SAGD), steam and solvent are co-injected. During the ES-SAGD process, a small amount of solvent with boiling temperature close to the steam temperature under operating conditions is co-injected with steam in a vapor phase in a gravity process similar to the SAGD process. The solvent condenses with steam at the boundary of the steam chamber. The condensed solvent dilutes the oil and reduces its viscosity in conjunction with heat from the condensed steam. This process offers higher oil production rates and recovery with less energy and water consumption than those for the SAGD process, and less solvent usage that VAPEX. Experiments conducted with two-dimensional models for Cold Lake-type live oil showed improved oil recovery and rate, enhanced non-condensable gas production, lower residual oil saturation, and faster lateral advancement of heated zones (Nasr and Ayodele, 2006). A solvent assisted SAGD is shown in FIG. 3 and is described in U.S. Pat. Nos. 6,230,814 and 6,591,908. It has been shown that combining solvent dilution and heat reduces oil viscosity much more effectively than using heat alone.
It is proposed that as the solvent condenses, the viscosity of the hydrocarbons at the steam-hydrocarbon interface decrease. As the steam front advances, further heating the reservoir, the condensed solvent evaporates, and the condensation-evaporation mechanism provides an additional driving force due to the expanded volume of the solvent as a result of the phase change. It is further believed that the combination of reduced viscosity and the condensation-evaporation driving force increase mobility of the hydrocarbons to the producing well.
Because of the cost of the injected solvents, they are usually recovered and recycled. Typically, the solvents are recovered by injecting steam back into the formation to vaporize the solvents and drive them out for recovery. One feature of the ES-SAGD process is that the recovered solvent can be re-injected into the reservoir. The economics of a steam-solvent injection process depends on the enhancement of oil recovery as well as solvent recovery. The lower the solvent retention in the reservoir the better the economics of the process.
There are three major factors that could affect production: gravity and viscous flow, heat conduction, and mass diffusion and dispersion. In any event, sufficient heat and solvent need to be introduced to the bitumen at a rate that is both economically and physically feasible, thereby mobilizing the bitumen to the production well.
Therefore, there is the need to find the optimal strategy for when and how to introduce solvent for ES-SAGD process to reduce solvent retention in the reservoir and improve economics of the process.